ORDER NUMBER

C-1-25

 

IN THE MATTER OF

the Utilities Commission Act, RSBC 1996, Chapter 473

 

and

 

British Columbia Hydro and Power Authority

Application for a Certificate of Public Convenience and Necessity for the

1L243 Transmission Load Increase (Highland Valley Copper) Project

 

BEFORE:

M. Jaccard, Panel Chair

E. A. Brown, Commissioner

 

on February 12, 2025

 

ORDER

WHEREAS:

 

A.      On May 23, 2024, British Columbia Hydro and Power Authority (BC Hydro) filed an application with the British Columbia Utilities Commission (BCUC) pursuant to sections 45 and 46 of the Utilities Commission Act (UCA), for a Certificate of Public Convenience and Necessity (CPCN) for the 1L243 Transmission Load Increase (Highland Valley Copper) Project (Project) (Application);

B.      The objective of the Project is to accommodate a request from Teck Resources Limited (Teck) for an increase in its contract demand under its Electricity Supply Agreement for Teck’s Highland Valley Copper operations from 146 Mega-Volt Amperes (MVA) to 180 MVA by December 2026. The increase in contract demand is needed to provide power for Teck’s Highland Valley Copper Mine Life Extension project, located north of Merritt, BC;

C.       The Project consists of the following activities:

a.       Reconductor transmission line 1L243 to increase its capacity and replace or reinforce structures where required;

b.       Supply and install a 300 MVA 230/138 kilovolt (kV)/12.6 kV transformer at Nicola substation;

c.       Upgrade the disconnect switches and wire/cable infrastructure at the Highland substation; and

d.       Construct a new line tap to connect Teck’s new Bethlehem substation to transmission line 1L055, at Teck’s expense and under BC Hydro’s supervision;

D.      By Orders G-156-24, G-187-24, and G-248-24, the BCUC established and amended a regulatory timetable for review of the Application, which included public notice, intervener registration, one round of information requests (IRs), letters of comment, Panel IRs, and final and reply arguments;

E.       Colin Parkinson; Lower Nicola Indian Band (LNIB); Nlaka’pamux Nation Tribal Council (NNTC); Residential Consumer Intervener Association (RCIA); British Columbia Old Age Pensioners’ Organization et al. (BCOAPO); Commercial Energy Consumers Association of British Columbia (the CEC); and Teck Highland Valley Copper Partnership (Teck) registered as interveners in this proceeding;

F.       During the proceeding, BC Hydro filed documents with the BCUC for which it requested confidential treatment. By Order G-156-24, the BCUC granted BC Hydro’s request for certain information to be held confidential until determined otherwise by the BCUC; and

G.      The BCUC has considered the Application, evidence and submissions in this proceeding and finds that the Project is in the public interest and the following determinations are warranted. 

 

NOW THEREFORE for the reasons outlined in the decision accompanying this order, the BCUC orders as follows:

 

1.       A CPCN is granted to BC Hydro for the Project.

2.       BC Hydro is directed to file Project reports as outlined in Section 10 of the Decision.

3.       BC Hydro is directed to file an application with the BCUC for a review of Tariff Supplement No. 6 by no later than September 30, 2025.

4.       The information filed confidentially during the course of this proceeding will be held confidential unless the BCUC determines otherwise.

 

DATED at the City of Vancouver, in the Province of British Columbia, this      12^th      day of February 2025.

 

BY ORDER

 

Electronically signed by Mark Jaccard

 

M. Jaccard

Commissioner

 

 

 

 

 

British Columbia Hydro and Power Authority

Application for a Certificate of Public Convenience and Necessity for the 1L243 Transmission Load Increase (Highland Valley Copper) Project

 

 

 

Table of Contents

Page no.

Executive Summary. i

1.0   Introduction. 1

1.1        Regulatory Process. 1

1.2        Legal and Regulatory Framework. 2

1.3        Structure of the Decision. 3

1.4        System Overview.. 3

2.0   Project Need and Justification. 4

2.1        Mandatory Reliability Standards. 5

2.2        System Constraints. 5

3.0   Evaluation of Alternatives. 7

3.1        System Interconnection Process. 7

3.2        Evaluation of Alternatives for 1L243 Capacity Upgrade. 8

3.3        Alternatives for Transformation at Nicola Substation. 10

4.0   Project Schedule, Procurement Strategy and Risks. 13

4.1        Project Schedule. 14

4.2        Procurement. 14

4.3        Project Risks and Risk Treatment. 15

5.0   Project Cost Estimate and Bill Impact. 16

5.1        Capital Cost Estimate. 16

5.2        Bill Impact. 17

6.0   Tariff Supplement No. 6. 19

7.0   Project Consultation and Engagement. 21

7.1        Indigenous Consultation. 21

7.1.1     Approach to Indigenous Consultation. 22

7.1.2     Indigenous Consultation Process. 23

7.2        Public Engagement. 28

8.0   Project Alignment with Provincial Energy Objectives and the Integrated Resource Plan. 29

9.0   Overall Panel Determination. 32

10.0 Project Reporting. 33

 

APPENDICES

 

Appendix A       List of Acronyms

Appendix B       Exhibit List

 

               

Executive Summary

On May 23, 2024, British Columbia Hydro and Power Authority (BC Hydro) filed an application with the British Columbia Utilities Commission (BCUC) pursuant to sections 45 and 46 of the Utilities Commission Act, for a Certificate of Public Convenience and Necessity (CPCN) for the 1L243 Transmission Load Increase (Highland Valley Copper) Project (Project).

 

The Project seeks to accommodate a request from Teck Resources Limited (Teck) for an increase in its contract demand for Teck’s Highland Valley Copper operations from 146 Mega-Volt Amperes (MVA) to 180 MVA by December 2026. The increase in contract demand is needed to provide power for Teck’s Highland Valley Copper Mine Life Extension project to extend the mine’s life to 2043.

 

The scope of the Project includes upgrades to the 1L243 transmission line, the addition of a transformer at Nicola substation, upgrades to various equipment at Highland substation, and a new line tap from Teck’s new Bethlehem substation (to be built) to transmission line 1L055. This last component will be designed, installed and paid for by Teck, under BC Hydro’s supervision.  The new line tap will become part of BC Hydro’s facilities when it is completed. The Project has an authorized cost of $147.1 million.

 

The Panel finds the Project to be in the public interest and grants a CPCN for the Project as proposed in the Application. The Panel is satisfied that BC Hydro has justified the need for the project as it has an obligation to make reasonable efforts to address customers’ requests for load increases, subject to its ability to supply.

 

The existing transmission infrastructure in the area cannot accommodate the requested increase in demand due to equipment constraints and the need to maintain compliance with Mandatory Reliability Standards. BC Hydro’s assessment during its planning process identified transmission system constraints and means to overcome them in order to provide the requested supply. The Panel is persuaded that the proposed alternative to upgrade the 1L243 transmission line is superior to twinning the line because of lower costs, lower environmental impacts, lower stakeholder impacts, lower impacts to Indigenous nations, and an ability to meet the required in-service date. To increase the transformation capacity constraint at the Nicola substation, the Panel concurs with the choice of installing a new 300MVA transformer given that the operational benefits outweigh the cost difference of installing a smaller transformer. The Panel finds the scope and cost of the proposed solution, which was presented as a single viable alternative, to be reasonable. The Panel finds that BC Hydro’s consultation with First Nations and Indigenous organizations has been adequate, and its public engagement has been sufficient. Furthermore, the Panel finds that the Project aligns with the applicable BC energy objectives and BC Hydro’s 2021 Integrated Resource Plan.

 

BC Hydro’s transmission system reinforcement and transmission extension policies, including the allocation of costs between customers and BC Hydro, is set in its Electric Tariff Supplement No. 6. The Panel notes that this tariff supplement has a cost allocation methodology that does not recognize the revenue impacts of term-limited projects, or the cost of energy in times when BC Hydro operates in an energy and/or capacity deficit. In addition, the Panel notes that provincial electrification policies may increase the number of future industrial customer interconnection requests, making the need for a review of the cost allocation methodology of increased importance. Given the above and that this tariff supplement was approved in 1991, the Panel considers that a review of Tariff Supplement No. 6 is warranted. Therefore, the Panel directs BC Hydro to file an application with the BCUC for the review of Tariff Supplement No. 6 by no later than September 30, 2025.

1.0              Introduction

On May 23, 2024, British Columbia Hydro and Power Authority (BC Hydro) filed an application with the British Columbia Utilities Commission (BCUC) pursuant to sections 45 and 46 of the Utilities Commission Act (UCA), for a Certificate of Public Convenience and Necessity (CPCN) for the 1L243 Transmission Load Increase (Highland Valley Copper) Project (Project) (Application).

 

The Project seeks to accommodate a request from Teck Resources Limited (Teck) for an increase in its contract demand under its Electricity Supply Agreement for Teck’s Highland Valley Copper operations from 146 Mega-Volt Amperes (MVA) to 180 MVA by December 2026. The increase in contract demand is needed to provide power for Teck’s Highland Valley Copper Mine Life Extension project, located north of Merritt, BC.[1]

 

The Project’s major items and scope are the following:[2]

•        Reconductor transmission line 1L243 to increase its capacity and replace or reinforce structures where required;

•        Supply and install a 300 MVA 230/138 kilovolt (kV)/12.6 kV transformer at Nicola substation; and

•        Upgrade the disconnect switches and wire/cable infrastructure at the Highland substation.

 

Teck will build a new Bethlehem substation within Teck’s permitted mine area as part of Teck’s electrical facilities. This substation is not part of the Project scope.[3] In addition, Teck will construct a new line tap to connect its new Bethlehem substation to transmission line 1L055. Teck will design and install the new line tap on behalf of BC Hydro, at Teck’s expense and under BC Hydro’s supervision. Because the new line tap will become part of BC Hydro’s facilities when it is completed, it is part of the scope of the Project for which BC Hydro is seeking approval.[4]

 

The Project has a total cost range of $110.3 million to $147.1 million, which is based on an expected cost of $123.6 million and an authorized cost of $147.1 million.[5] The Project’s planned in-service date is December 2026.[6]

1.1              Regulatory Process

The BCUC established and amended a regulatory timetable for review of the Application, which consisted of public notice, intervener registration, one round of information requests (IRs), letters of comment, Panel IRs, and final and reply arguments.[7]

 

Seven interveners registered in the proceeding: Colin Parkinson; Lower Nicola Indian Band (LNIB); Nlaka’pamux Nation Tribal Council (NNTC); Residential Consumer Intervener Association (RCIA); British Columbia Old Age Pensioners’ Organization et al. (BCOAPO); Commercial Energy Consumers Association of British Columbia (the CEC); and Teck Highland Valley Copper Partnership (Teck). For the purposes of this decision, Teck Resources Limited and Teck Highland Valley Copper Partnership are referred to as Teck.

 

1.2              Legal and Regulatory Framework

Sections 45 and 46 of the UCA set out the legislative framework for the BCUC review of CPCN applications. Section 45(1) of the UCA states that except as otherwise provided, after September 11, 1980, a person must not begin the construction or operation of a public utility plant or system, or an extension of either, without first obtaining a CPCN from the BCUC.[8]

 

Section 46(3) of the UCA states that the BCUC may issue or refuse to issue a CPCN or may issue a CPCN for the construction or operation of only a part of the proposed facility, line, plant, system or extension, and may attach terms and conditions to the CPCN.

 

In addition to considering the interests of persons in the province who receive or may receive service from BC Hydro, section 46(3.3) of the UCA requires that the BCUC consider the following in determining whether to issue a CPCN to BC Hydro:

a) British Columbia's energy objectives;[9]

b) the most recent of the following documents:

i. an integrated resource plan approved under section 4 of the Clean Energy Act[10] before the repeal of that section;

ii. a long-term resource plan filed by BC Hydro under section 44.1 of the UCA; and

c) the extent to which the application for the CPCN is consistent with the applicable requirements under section 19 of the Clean Energy Act.

The BCUC’s CPCN Guidelines provide general guidance regarding the information that should be included in a CPCN application and the flexibility for an application to reflect the specific circumstances of the applicant, the size and nature of the project and the issues raised by the application.[11]

 

The BCUC’s 2010 First Nations Information Filing Guidelines for Crown Utilities identify the information that must be filed by Crown Utilities (of which BC Hydro is one) to allow the BCUC to assess whether the Crown’s duty to consult First Nations has been fulfilled.[12]

 

Section 125.2 (2) of the UCA provides the BCUC with exclusive jurisdiction to determine whether a reliability standard is in the public interest and should be adopted in BC. The term “reliability standard” is defined in section 125.2 (1) of the UCA as:

a reliability standard, rule or code established by a standard-making body for the purpose of being a mandatory reliability standard for planning and operating the North American bulk electric system, and includes any substantial change to any of those standards, rules or codes.

 

Section 125.2(6) of the UCA states that the BCUC must, by order, adopt reliability standards if the BCUC considers that the reliability standards are required to maintain or achieve consistency in BC with other jurisdictions that have adopted the reliability standards.

1.3              Structure of the Decision

The structure of this Decision largely follows that of the Application and the BCUC’s CPCN Guidelines.

•         Section 2 addresses the Project need and its justification;

•         Section 3 discusses the evaluation of alternatives that BC Hydro considered;

•         Section 4 outlines the Project schedule, procurement strategy and risks description;

•         Section 5 describes the Project cost and bill impact;

•         Section 6 addresses Tariff Supplement No. 6;

•         Section 7 discusses Indigenous consultation and public engagement;  

•         Section 8 addresses the BC energy objectives, the Integrated Resource Plan and other policy considerations under section 46 (3.3) of the UCA that the BCUC must consider in determining whether the Project is in the public interest;

•         Section 9 sets out the Panel’s determinations; and

•         Section 10 details the BCUC directives relating to detailed reporting requirements.

 

Relevant evidence and arguments submitted by the applicant and interveners are summarized in each section.

1.4              System Overview

In this section, we provide an overview of BC Hydro’s transmission system in the area near Teck’s operations.

 

The Highland Valley area is served by BC Hydro’s South Interior West Regional Transmission system including four BC Hydro substations and six transmission lines as shown in Figure 1 below:[13]

 

 

 

Figure 1: Highland Valley Area and General Project Location

 

 

 

2.0              Project Need and Justification

This Project need arises from Teck’s request to increase its contract demand from 146 MVA to 180 MVA to provide power for Teck’s Highland Valley Copper Mine Life Extension Project, by December 2026.[14]

 

BC Hydro’s Electric Tariff Supplement No. 5 requires that, subject to BC Hydro’s ability to supply, BC Hydro make reasonable efforts to respond to transmission customer requests for load increases, provided that such increase is subject to Appendix 1 of BC Hydro’s Electric Tariff Supplement No. 6.[15] BC Hydro’s Electric Tariff Supplement No. 6 provides BC Hydro’s transmission system reinforcement and transmission extension policies,[16] including the allocation of costs between customers requesting service and BC Hydro.[17]

 

In this case, BC Hydro states it can supply Teck’s requested 34 MVA increase in contract demand from existing and planned resources and, accordingly, is required to make reasonable efforts to respond to the request.[18] The Project requires BC Hydro to make upgrades to its existing system in order to serve the additional load without compromising system constraints and reliability standards.

 

In this section, we briefly explain the salient aspects of the relevant reliability standard that must be considered, and we identify the constraints that must be overcome for BC Hydro’s system to supply Teck’s additional load.

 

2.1              Mandatory Reliability Standards

BC Hydro states it must comply with the requirements of the applicable Mandatory Reliability Standards (MRS) approved for adoption by the BCUC.[19] Reliability standards define reliability requirements for planning and operating the North American bulk power system which focus on performance, risk management and facility capabilities. Together with BC Hydro’s technical interconnection requirements and additional system studies, BC Hydro ensures that MRS criteria are satisfied when customers connect to the BC Hydro system. If there are any negative impacts to the system or the system is constrained by a customer’s interconnection request, BC Hydro must implement system upgrades as required.[20] Reliability standards must therefore be considered in analyzing system constraints and determining solutions to overcome them.

 

The Transmission System Planning Requirements standard TPL-001-4 requires BC Hydro to plan its transmission system to ensure the system will continue to provide service during certain contingency events under peak load conditions.[21]  The specific contingency events applicable to the Project are referred to as P1 and P3, which are defined as follows:[22]

•         P1 contingencies are defined in MRS TPL-001-4 as “Normal System followed by loss of one of the following: Generator; Transmission Circuit; Transformer; Shunt Device; or Single pole of a DC line”. P1 Contingencies are also known as a “N-1” (“N minus one”) contingencies; and

•         P3 contingencies are defined in MRS TPL-001-4 as “Loss of a generator unit followed by loss of one of the following: Generator; Transmission Circuit; Transformer; Shunt Device; or Single pole of a DC line”. P3 contingencies are otherwise known as a “N-G-1” contingencies.

Each event represents a compromised state of the bulk electric system due to certain power system elements being out of service. In order to develop appropriate transmission planning assessments as required by TPL-001-4, BC Hydro must ensure that proposed solutions do not overload the system under a P1 or P3 contingency event. The details of the system constraints BC Hydro must assess under the MRS as they pertain to the Project are discussed in the subsection below.

2.2              System Constraints

A System Impact Study completed in 2020 identified that the existing transmission and substation infrastructure cannot accommodate Teck’s requested increase in contract demand due to existing system constraints.[23] BC Hydro identifies three system constraints which must be addressed to accommodate Teck’s requested increase in contract demand.

 

The first system constraint is a limitation in the 1L243 transmission line capacity in summer peak load conditions during contingency events. BC Hydro studied the loss of the 2L265 transmission line between Nicola and Valleyview substations, a P1 contingency event. This event results in the 1L243 transmission line exceeding its summer normal conductor rating by 120%, thus requiring thermal upgrade of 1L243 to accommodate Teck’s increased demand. BC Hydro also considered the potential further loss of the Merritt Green Energy Plant generator which would result in a P3 contingency.[24]

 

The second system constraint is insufficient step-down transformation capacity at Nicola substation under a contingency event.[25] One such event studied by BC Hydro includes a loss of one Nicola substation 230/138kV transformer representing a P1 contingency event. This event would result in overloading the remaining similarly-sized transformer at Nicola, which could cause equipment damage and resulting impacts on the 138kV system. The impacts of this contingency event would be exacerbated by the loss of the Merrit Green Energy Plant generator under a P3 contingency.[26]

 

The third system constraint is the insufficient rating of the existing disconnect switches and associated station infrastructure at the Highland substation. The existing transmission line 1L055 is capable of accommodating Teck’s requested load increase; however, the disconnect switches and associated station infrastructure for 1L055 at Highland substation are not and, therefore, must be upgraded.[27]

 

In summary, BC Hydro states it is required to accommodate Teck’s requested increase in contract demand by December 2026, if it is feasible to do so.[28] The existing transmission infrastructure in the area cannot accommodate the requested increase in demand due to equipment constraints and the need to maintain compliance with MRS as described above. BC Hydro states it therefore should accommodate Teck’s request by upgrading the capacity of transmission line 1L243, transformation capacity at Nicola substation, and equipment at Highland substation.[29]

 

Position of the Parties

No interveners provided comments on BC Hydro’s operational constraints arising from the Project. However, BCOAPO notes that various contingencies give rise to system reinforcement requirements and submits that, subject to Teck and BC Hydro executing a facilities agreement, there will be a need for BC Hydro to undertake the Project.[30]

 

In Final Argument, Teck submits that to continue to operate its facility, increased service from BC Hydro is required.[31] Teck submits that BC Hydro has clearly identified that the Project enables Teck’s service request increase and that BC Hydro has considered all feasible alternatives that comply with BC Hydro’s mandated operating standards and requirements.[32] Further, Teck submits that the Project will provide greater system benefit as it will improve the availability and reliability of electricity in the area.[33]

 

Panel Determination

Teck has requested an increase in its contract demand under its Electricity Supply Agreement with BC Hydro. The Panel accepts BC Hydro’s analysis of the capacity of the existing transmission and substation infrastructure to accommodate the proposed load and maintain the required level of reliability of operation under P1 and P3 contingency events as defined in MRS Standard TPL-001-4. The Panel is persuaded that without making necessary modifications to overcome the system constraints of insufficient 1L243 line capacity, insufficient ratings on equipment at the Highland substation and insufficient step-down transformer capacity at the Nicola substation, the system cannot accommodate Teck’s requested increase. In accordance with BC Hydro’s Electric Tariff Supplement No. 5, Clause 6(a) the Panel observes BC Hydro is required to make reasonable efforts to respond.  

 

BC Hydro and Teck have voiced their support for the Project and no parties have expressed opposition to its need. The Panel finds that there is a need for a project to address the constraints of BC Hydro’s existing infrastructure to accommodate Teck’s requested increase in contract demand.

3.0    Evaluation of Alternatives

Up to the time of the 2020 Feasibility Study, BC Hydro’s focus was the transmission line constraint. Two viable alternatives emerged from the study: a 1L243 line capacity upgrade or a new parallel line alongside 1L243. BC Hydro subsequently deemed only one of these viable and concluded that the Project qualifies as an Interconnection Single Viable Alternative (ISVA) in BC Hydro’s Transmission Load Interconnection Process.[34] The need for transformation reinforcement at Nicola substation was identified later, from the 2020 System Impact assessment with a transformer addition as the only viable alternative identified to address this constraint. Further, through the course of the proceeding additional alternatives were explored through IRs, all of which BC Hydro deemed to be infeasible or inferior options.

 

The sections below start by explaining BC Hydro’s internal interconnection process. Subsequent sections are ordered in accordance with the project’s historical development, with two alternatives to address a shortfall in capacity of transmission line 1L243 first discussed, followed by two options for addressing a shortfall in transformation capacity at Nicola substation. As the scope to address the under-rated equipment at Highland substation is proposed with a single alternative, this is not explored here but is part of the overall Project scope in Section 4.

3.1              System Interconnection Process

A transmission customer seeking a load increase must work with BC Hydro through its Transmission Load Interconnection Process, which involves BC Hydro assessing the impacts of the customer’s request on BC Hydro’s system.[35] System upgrades are sometimes required to mitigate system constraints or maintain compliance with Mandatory Reliability Standards (MRS). BC Hydro’s Electric Tariff Supplement No. 6 identifies the allocation of system upgrade costs between the customer and BC Hydro,[36] which is discussed further in Section 6.0 of this Decision.

 

BC Hydro has a defined Transmission Load Interconnection Process shown in Figure 2 below.

 

Figure 2: Transmission Load Interconnection Process[37]

 

 

To evaluate Teck’s increased capacity request, BC Hydro initiated its Transmission Load Interconnection Process with Teck and assessed different project options with increasing levels of depth over several years.[38] Through this process, BC Hydro and Teck evaluated 12 alternatives for different Teck load requirement scenarios to accommodate an increase in demand at Teck’s facility.[39] In 2020, at Teck’s request, BC Hydro conducted a Feasibility Study which identified two alternatives to be considered for Teck’s increased demand: (1) reinforcement of the 1L243 circuit (the Project) and (2) building a new transmission line between the Nicola and Highland substations.[40]

 

3.2              Evaluation of Alternatives for 1L243 Capacity Upgrade

BC Hydro’s 2020 Feasibility Study provides a comparative analysis of the two alternatives identified to address the insufficient 1L243 line capacity, reproduced in Table 1 below. BC Hydro states the analysis shows reinforcing 1L243 would have lower ratepayer impacts, lower environmental impacts, lower stakeholder impacts and lower Indigenous impacts. Further, BC Hydro states that reinforcing 1L243 can meet Teck’s requested in-service date of December 2026. BC Hydro considers that the 1L243 reinforcement alternative is clearly a better option.[41]

 

Table 1: 2020 Feasibility Study Comparative Analysis of New Line and Upgrade Alternatives[42]

 

Following the 2020 Feasibility Study, Teck requested that BC Hydro conduct a System Impact Study that would review the implications and feasibility of increasing capacity on transmission line 1L243 from Nicola to Highland substation to accommodate Teck’s contract demand increase to 180MVA.[43] BC Hydro’s base case for this System Impact Study included all of the interconnection requests in the area that had entered the queue before Teck.[44] The results of this System Impact Study identified that, in addition to the reinforcement of the 1L243 transmission line, the Nicola substation would require additional transformation capacity and the Highland substation would require upgrades.[45] Upon completion of the System Impact Study in 2020, the Project was released as an Interconnection Single Viable Alternative.[46]

 

Several potential alternatives to upgrading 1L243 were raised during the proceeding including a Remedial Action Scheme (RAS) without load shedding, local generation and the Kwoiek Creek Independent Power Producer (IPP) with battery storage.[47] BC Hydro states that a RAS to trip a 1L243 terminal upon loss of 2L265[48] would cause system voltage instability under peak load conditions.[49] Further, Teck requires firm service and does not want its supply disrupted by load shedding arising due to a contingency.[50] BC Hydro states that any local generation must be a dispatchable resource, where the output can be adjusted by BC Hydro to meet various conditions.[51] BC Hydro cannot speculate on future IPPs being able to reliably serve the additional load requested by Teck in the region.[52] Finally, BC Hydro states that the intermittent power of Kwoiek Creek IPP could not offset the increased demand even with the addition of utility grade storage facilities local to the Project.[53]

 

3.3              Alternatives for Transformation at Nicola Substation

As part of the evaluation of the transformation constraint at Nicola substation, BC Hydro states it has considered the pre-Project conditions to include all forecast and in-queue loads over the planning horizon, in accordance with its interconnection queue management policies. BC Hydro notes that if the evaluation of Teck’s requested load increase did not include any additional in-queue loads, Nicola substation would not have a transformation constraint. However, when BC Hydro evaluates Teck’s demand increase coupled with all the lower queued interconnection customers, in accordance with its interconnection queue management policies, Nicola substation experiences a transformation constraint and Teck’s demand increase triggers the need for system reinforcement. Further, BC Hydro identifies that it is likely that the Nicola 230/138kV transformer addition would be triggered by the next customer in the interconnection queue regardless.[54]

 

BC Hydro states it considered two alternatives for increasing the 230/138kV transformation capacity at Nicola substation: (1) installing a 300MVA transformer or (2) installing a transformer with less capacity. BC Hydro states it chose the 300MVA transformer because of the nominal cost increase, operational ease with similar-sized transformers already installed, and additional future operational flexibility from the increased capacity.[55]

 

BC Hydro addressed a possible alternative to mitigating system transformation constraints at Nicola substation using a Remedial Action Scheme (RAS) which would not result in shedding load. However, BC Hydro explains that it does not generally rely on a RAS to serve firm loads for an extended period since taking system elements out of service via a RAS would reduce system reliability and hinder BC Hydro’s ability to respond to other system events. BC Hydro also considers other factors such as the potential for future loads and future asset sustainment needs when assessing potential system upgrades. Given the possibility of reduced system reliability and future sustainment needs of BC Hydro’s system, BC Hydro concludes that a RAS would not be a suitable alternative to mitigate the transformation constraint at Nicola substation.[56]

 

Position of the Parties

Teck submits in its Final Argument that BC Hydro has considered all feasible alternatives for the Project. Teck adds that BC Hydro has clearly set out the components to the Project which address the three identified system constraints and has provided a thorough overview of its determination that these components are the preferred alternatives for the Project after its consideration of feasible alternatives.[57]

 

RCIA submits it is satisfied with the provided justification for selection of a 300 MVA transformer for the Nicola substation.[58]

 

BCOAPO submits that it supports the Project as the preferred alternative.[59]

 

RCIA submits that the information filed on the 12 project alternatives does not meet the BCUC’s CPCN Guidelines and that BC Hydro’s alternatives analysis lacks sufficient justification and detail with respect to comparison of costs, benefits and associated risks and feasible alternatives.[60] RCIA recommends BC Hydro provide all alternatives considered in future CPCN filings.[61]

 

Similarly, the CEC states that it expects BC Hydro to provide a fulsome analysis of all Project alternatives, including an economic comparison of all technically feasible alternatives for any major project application.[62] The CEC concludes that BC Hydro “… has not thoroughly captured, satisfactorily discussed, or fully developed or evaluated alternatives to the Project in the Application.”[63] The CEC submits that it cannot effectively comment on the comparative analysis of the transmission line project alternatives as BC Hydro did not complete a System Impact Study for the new line alternative and did not provide a cost-benefit analysis concerning future forecast transmission loads.[64]

 

In response to RCIA and the CEC regarding the assessment of alternatives, BC Hydro states that after numerous alternatives were identified for the Project, only the alternative to upgrade the existing line remains viable and is the only alternative that meets the customer’s required in-service date.[65] Further, BC Hydro submits that it was not necessary to perform a cost-benefit analysis as the new line was not a viable alternative since it did not meet Teck’s requested in-service date .[66]

 

In its Final Argument, Teck agrees with BC Hydro’s conclusion that the use of a RAS that includes load shedding as a means to address the identified system constraints associated with this project would be prohibited under the Mandatory Reliability Standards, and would not be a viable alternative for the 1L243 line upgrade.[67]

 

The CEC submits that BC Hydro did not allow for sufficient consideration of a RAS in its alternatives analysis. The CEC submits that it was within the purview of BC Hydro to conduct detailed RAS studies to inform its investigation of Project alternatives and that a development of cost estimates for any corresponding RAS solutions would have further helped BC Hydro’s consideration and comparative analysis of the alternatives.[68]

 

In reply, BC Hydro submits that it explained the circumstances in which it considers a non-load shedding RAS, and why it did not consider one appropriate for this Project. Specifically, BC Hydro submits that a RAS that removes an additional transmission grid element from service in response to a system contingency would be contrary to good utility practice except in emergency situations and not appropriate for long-term planning.[69]

 

The CEC submits that BC Hydro could have more thoroughly explored options for local power generation as a Project alternative. The CEC estimates that BC Hydro’s work to review and study alternatives spans approximately nine years, which should be a satisfactory planning horizon for BC Hydro to examine local power supply options as part of its interconnection process.[70]

 

In reply, BC Hydro submits that Teck’s project evaluation does not represent a nine-year planning horizon as the CEC asserts. Following early customer engagement in 2015, Teck did not formally enter the Load Interconnection Process until 2019, with BC Hydro completing its Feasibility Study in 2020. BC Hydro submits it does not have control over the timing and loads associated with transmission load interconnection projects and, as a result, may not have the same range of viable alternatives that might be available to solve a system need. BC Hydro also submits that the uncertainty surrounding future IPP projects does not allow them to be included in BC Hydro’s system impact studies and that there is no evidence that there is any dependable IPP proposed for the area.[71]

 

Panel Determination

The Panel observes that BC Hydro has applied its own robust process and has identified and evaluated project alternatives for the different project objectives. 

 

For addressing the 1L243 line capacity concern, the two final options “New Line” and “Upgrade Alternative” were contemplated in BC Hydro’s 2020 comparative feasibility evaluation as reproduced in Table 1. The Panel is persuaded that the proposed “Upgrade Alternative” is superior by way of lower costs, lower environmental impacts, lower stakeholder impacts, lower impacts to Indigenous nations and an ability to meet the required in-service date. While a comparison of viable alternatives is generally expected to include numeric parameters rather than descriptive comparators, in this case the Panel disagrees with the CEC that this is required.  

 

In addition, while an evaluation to eliminate non-viable alternatives is generally expected to incorporate a range of criteria, the Panel agrees with BC Hydro that the consideration of timing is of particular importance in this case. Unlike BC Hydro initiated capital projects carried out to maintain and/or enhance the transmission network with benefits accruing in varying ways to many or all customers, the Project is being driven by the needs and timeline requested by Teck.

 

To increase the 230/138kV transformation capacity at the Nicola substation, the Panel notes that two feasible options were identified and concurs with the choice made of purchasing a 300MVA transformer due to the operational benefits achieved outweighing the nominal cost difference.

 

In the Panel’s opinion a comprehensive analysis of the only viable and the superior alternative for each of the transmission line and the Nicola substation respectively is sufficient given the rationale provided in this case. BCOAPO and Teck are supportive of the decision methodology used by BC Hydro. The Panel acknowledges RCIA and CEC’s reluctance to accept the evaluation of alternatives but finds BC Hydro’s analysis, encapsulated in the comparison in Table 1, adequate to find the 1L243 reinforcement alternative superior and agrees with the election to abandon the new line alternative. Correspondingly, it appears reasonable to the Panel that the Project has been assigned Interconnection Single Viable Alternative (ISVA) status in BC Hydro’s Transmission Load Interconnection Process.

 

The Panel concurs that a load shedding RAS is not appropriate for serving long-term, firm loads. Although adopting a non load shedding RAS solution instead of a new transformer at Nicola substation is technically viable and would likely present a cost saving opportunity because the transformer would not be necessary, the Panel does not find that more analysis than already undertaken is needed to investigate this further as suggested by the CEC. As explained by BC Hydro, a RAS would be an unconventional solution contrary to good utility practice. The Panel finds this explanation for discounting a RAS reasonable. 

 

Due to the BCUC’s and interveners’ explorations of the non load shedding RAS alternative, the evidentiary record now provides a sufficient evaluation of this technically feasible, but ultimately not viable, option. To arrive at a sufficient set of evidence, however, numerous lines of inquiry were required as part of the proceeding. These questions may have been avoided, and the corresponding regulatory burden reduced, had BC Hydro explained the rationale for including or excluding technically feasible options in its Application.

4.0              Project Schedule, Procurement Strategy and Risks

BC Hydro’s Project includes the following three major scope items: [72]

•         Reconductor transmission line 1L243 to increase its capacity and replace or reinforce structures where required

•         Supply and install a 300 MVA 230/138 kV/12.6 kV transformer at Nicola substation; and

•         Upgrade the disconnect switches and wire/cable infrastructure at the Highland substation.

In addition, BC Hydro states it will upgrade the protection and control systems at the Nicola and Highland substations as well as perform related upgrades at the control centers in the Fraser Valley and South Interior. A new revenue metering point will be installed for the new Teck-owned and operated Bethlehem substation and the existing revenue metering at Teck’s Lower-Level Dam substation will be replaced.[73]

Teck is constructing the Bethlehem substation, a new Teck-owned and operated substation, at its own expense as part of its electrical facilities to receive a portion of the increased contract demand. This new Bethlehem substation will require a new line tap to connect to the existing 1L055 transmission line.[74] Teck will design and install the new line tap on behalf of BC Hydro, at Teck’s expense, and under BC Hydro’s supervision. Once completed, this line tap will become part of BC Hydro’s facilities and, therefore, it is part of the scope of the Project.[75]

 

BC Hydro states that the Project does not trigger environmental impact assessments under either the Federal Impact Assessment Act or the British Columbia Environmental Assessment Act. The Project access upgrades will require a permit under section 11 of the Water Sustainability Act.[76]

 

In the following sections the schedule, procurement strategy and preliminary risk analysis are provided for the proposed Project scope.

 

4.1              Project Schedule

BC Hydro provides a Project schedule with an in-service date in December 2026, as described in Table 2 below:[77]

 

 Table 2: Project Major Milestones

 

BC Hydro states that the Project schedule is the result of a combination of required Project activities, construction period constraints and Teck’s requested in-service date.[78]

 

BC Hydro notes that the final Project completion date is later than typical projects due to a three-year weed mitigation and monitoring program that will run from the in-service date to the completion date. This program is based on a weed mitigation and monitoring plan that was completed for a previous project in the same area and will be part of the land use agreement with the private property owners.[79]

4.2              Procurement

BC Hydro states that the Project delivery method is Design-Bid-Build, with various procurement approaches being used to deliver the key scope elements, as follows:[80]

•         The design and supply of the 138kV underground cables, the supply of nonstandard steel and the supply and installation of the replacement storage building at Nicola substation will follow a public procurement process;

•         Supply of equipment and services will leverage existing BC Hydro master agreements; and

•         Various site work and services will see Indigenous procurement opportunities.

 

4.3              Project Risks and Risk Treatment

BC Hydro‘s project management practices dictate that risks and associated risk treatments have been and will be identified, analyzed, monitored and reviewed over the life of the Project. BC Hydro’s risk management activities include the following:[81]

a)       Risks are identified based on input from the Project team, operations and maintenance staff, as well as applicable lessons learned from similar past projects;

b)      A qualitative and/or quantitative risk analysis is performed for identified risks to determine their consequence type, severity, and likelihood. This analysis is then used to determine the required level of oversight;

c)       Treatment plans to respond to and mitigate risks are developed, with defined timelines and risk owners; and

d)      Risks and reporting of risks are monitored and reviewed regularly so that the appropriate audience is informed and required updates are made.

BC Hydro has identified two material risks for the definition phase of the Project and six material risks for the implementation phase, as listed below:[82]

•         Definition phase risks:

1)      A BCUC order granting a CPCN for the Project being issued later than anticipated resulting in increased costs and/or schedule delays: after treatment plans, this reputational risk remains at a level of possible with the potential effect of criticism from a small but vocal minority of customers;[83] and

2)      Private landowners could oppose definition phase activities that require access across private lands: this risk could impact the Project schedule and have a financial impact. After treatment plans, the financial risk remains at a level of possible and the financial impact has been calculated to be in the $100 thousand to $1 million range.[84]

•         Implementation phase risks:

1)      Construction worker activities in close proximity to energized lines and equipment could result in worker injury or fatality: after treatment plans, the residual risk is deemed very unlikely;[85]

2)      Wildfire, flood or mudslide impacts during field work or construction: after treatment plans, the residual risk is at a level of possible with a financial impact estimated at $1 million to $10 million;[86]

3)      Emergency work impacting other parts of BC Hydro’s system diverting construction crews: after treatment plans, the residual risk is at a level of remote with a financial impact estimated at $1 million to $10 million;[87]

4)      First Nations not accepting BC Hydro archaeological study results: this potential event is a risk of reputational damage to BC Hydro as well as Project delays. The residual risk is at a level of possible with the potential effect of criticism from a small but vocal minority of customers;[88]

5)      Global supply chain issues causing delay in delivery of equipment could impact the Project schedule and may also increase costs: the residual risk is assessed at a level of possible with the main consequence being reputational;[89] and

6)      Cost escalation is higher than expected: due to the unique current market conditions, there is a likelihood that cost escalation exceed the forecast escalation rates in the Application. BC Hydro has included a special reserve in the project reserves, which is intended in part to address the potential impact of higher cost escalations than expected. There is a residual risk is considered possible with a financial impact estimated at $1 million to $10 million.[90]

 

Positions of the Parties

Interveners did not make submissions on Project schedule, procurement strategy and/or risks.

 

Panel Determination

The Panel finds the Project as described reasonable, with no opposing views from the parties, and with the components suitable for addressing the system constraints described in Section 2 and reflecting the preferred solution described in Section 3.

 

The Panel notes that the Project schedule indicates that BC Hydro plans to meet Teck’s requested in-service date of December 2026. Since meeting Teck’s request includes an in-service date, it is of heightened importance that BC Hydro takes all measures reasonable to avoid delays during the project’s definition and implementation phases. 

 

The Panel acknowledges the procurement strategy and finds it a reasonable approach.

 

The Panel observes BC Hydro’s material definition phase risks of delays in the BCUC’s CPCN approval and site inaccessibility caused by private landowners’ opposition and finds them reasonable. Of the six identified material implementation phase risks, four identify events that could impact the Project schedule and BC Hydro’s proposed treatments reduce their risk of occurrence. Overall, from the evidence provided, the Panel finds the risks identified and the proposed mitigation measures reasonable. 

5.0              Project Cost Estimate and Bill Impact

The cost of the Project is expressed as a range to reflect project risks and other unanticipated impacts to deliver the Project scope described in Section 4. In addition, to demonstrate the effect of the Project costs on customer rates, this section summarizes the anticipated Project bill impact.

5.1              Capital Cost Estimate

The Project has a total cost range of $110.3 million to $147.1 million. This cost range is based on an expected cost[91] of $123.6 million (Expected Cost) and an authorized cost of $147.1 million (Authorized Cost).[92] The Expected Cost estimate is based on a preliminary design and conforms to the Association for the Advancement of Cost Engineering International (AACE) Class 3 cost estimate requirements with an estimated accuracy range of +14% to -11%.[93] The Authorized Cost is the sum of the Expected Cost and the project reserve of $23.5 million.[94]

 

The Project Cost Range includes life-to-date costs and forecast direct construction costs, indirect construction costs, contingency and reserves, escalation, interest during construction, and capital overhead.[95]

 

BC Hydro states that in March 2024, it applied for funding from the federal government’s Critical Minerals Infrastructure Fund to support the Project. If BC Hydro’s funding application is approved, it could receive up to 50 percent of eligible project costs, which would help reduce the increase in its revenue requirements and bill impacts. Given the uncertainty of the funding, BC Hydro is not relying on receiving any funding from the Critical Minerals Infrastructure Fund to support the Application. [96]

5.2              Bill Impact

The Project will impact BC Hydro’s revenue requirements, including operating costs, amortization, and finance charges. BC Hydro performed a bill impact analysis and estimates an increase in its revenue requirements of $6.3 million and a bill impact of 0.11 percent in fiscal 2028.[97] BC Hydro identifies the cumulative incremental bill impact as the incremental bill increase related to the Project’s assets at a future point in time, relative to today’s bill (i.e., fiscal 2024 bills, which include fiscal 2024 rates and the fiscal 2024 deferral account rate rider and trade income rate rider).[98]

 

BC Hydro provides the cumulative incremental bill impacts of the Project’s Expected and Authorized Cost estimates in Figure 3 below:

 

Figure 3: Project Cumulative Incremental Bill Impact – Expected and Authorized Cost[99]^, [100]

 

With both the Expected Cost and Authorized Cost estimates, there is an initial increase in BC Hydro’s revenue requirements as expenditures are incurred to dismantle existing assets, followed by another increase as the new assets are placed in service which results in higher amortization and finance charges being recovered from ratepayers. The cumulative incremental bill impact declines after fiscal 2028 mainly because of lower finance charges as amortization recovered from ratepayers is used to pay down the debt over time.[101]

 

BC Hydro states that the revenue requirements and bill impact analysis in the Application are based on the Expected Cost, which includes past expenses and projected direct and indirect construction costs, contingencies, escalation, interest during construction, and capital overhead. The analysis based on the Authorized Cost combines the Expected Cost with the Project Reserve.[102] BC Hydro states that, in line with its past practices regarding other growth capital projects, it does not factor in revenue from the incremental load in its revenue requirements and bill impact analysis in the Application.[103] However, in response to IRs, BC Hydro provided the revenue requirements and bill impact analyses that included the expected incremental revenue from and the estimated cost of energy of Teck’s additional load based on BC Hydro’s marginal cost of energy.[104]   

 

Position of Parties

No party opposed the capital cost estimate provided by BC Hydro.

 

With respect to the funding from Critical Minerals Infrastructure Fund, both BCOAPO and the CEC do not object to BC Hydro’s approach of not relying on receiving any funding from the fund to support the Application.[105]

 

The CEC and BCOAPO submit that the revenue requirement and bill impact analyses should include both the expected incremental revenue from the new load and the cost of energy to serve it for a more complete picture of project impacts and cost effectiveness.[106] BCOAPO submits that the BCUC should direct BC Hydro to provide such rate impact analyses in future CPCN applications that deal with projects that address transmission customer load increases.[107]

 

In reply, BC Hydro submits that it is prepared to include bill impact analyses of the kind requested by BCOAPO and the CEC. However, it submits that the BCUC should refrain from directing it to do so as BC Hydro should continue to have the discretion to determine what is necessary and appropriate to comply with the BCUC’s CPCN Guidelines relevant to the approval being sought.[108]

 

Panel Determination

The Panel finds as reasonable BC Hydro’s Authorized Cost estimate of $147.1 million that includes a project reserve of $23.5 million. The capital cost estimate is consistent with an AACE International Class 3 cost estimate, which aligns with the BCUC’s CPCN Guidelines. The Panel is satisfied with BC Hydro’s approach of excluding any potential Critical Minerals Infrastructure Fund funding in its revenue requirements and bill impact analysis given the uncertainty of receiving the funding.

 

While the Panel recognizes that the inclusion of the expected incremental revenue from new loads and the cost of energy to serve that load in the revenue requirements and bill impact analysis may be useful in evaluating projects that address transmission customer load increases, the Panel is not persuaded that a direction to BC Hydro to provide such analyses in all similar future CPCN applications is warranted. In the Panel’s view, such analyses may not be useful in evaluating all such projects, therefore utilities should have the discretion to determine what is necessary and appropriate to comply with the BCUC’s CPCN Guidelines based on the circumstances of each project. The Panel notes BC Hydro’s statement that it is prepared to include the analyses requested by BCOAPO and the CEC in future applications, and the Panel expects it to do so where appropriate.

6.0              Tariff Supplement No. 6

This section provides a discussion of Tariff Supplement No. 6 and how costs are allocated for projects to accommodate customer interconnection requests, and the cost allocation between Teck and BC Hydro for this Project. Tariff Supplement No. 6 was approved by the BCUC on January 21, 1991; it resulted from a negotiated settlement between BC Hydro and industrial customers and has not been modified since.[109]

 

Tariff Supplement No. 6 identifies how costs for new infrastructure required to connect a new load customer to the transmission system are allocated between BC Hydro and the customer. These costs are split into three categories:[110]

 

                     I.            Customer’s Facilities – The customer is required to build, own, operate, and pay for its facilities.

                   II.            Basic Transmission Extension – Any additions or alterations to existing BC Hydro facilities necessary to extend up to 90 meters to the customer’s facilities. The customer pays for all the costs associated with designing and implementing the Basic Transmission Extension.

                 III.            System Reinforcement – Additions and alterations to existing BC Hydro facilities necessary to supply a customer’s request. BC Hydro constructs, owns, and operates the System Reinforcement. An “offset,” which is treated as BC Hydro’s system costs, is applied towards these costs based on the provisions in Tariff Supplement No. 6. BC Hydro also obtains security from the customer equal to the “offset” amount. If the offset is insufficient to cover all of the System Reinforcement costs, then BC Hydro will also obtain a cash contribution from the customer for the difference between the System Reinforcement costs and the offset.

Under the terms of Tariff Supplement No. 6, BC Hydro provides an offset towards the System Reinforcement costs equal to the lesser of (i) the estimate of the System Reinforcement costs and (ii) the maximum offset calculated based on the following formula:[111]

 

 , where:

 

I = BC Hydro’s maximum offset towards the cost of System Reinforcement;

 

R = the incremental revenue as calculated by BC Hydro from the estimated incremental load during the first year of normal operations;

 

E = the estimated incremental operation and maintenance expense of supplying the incremental load during the first year of normal operations;

 

D = one-half of the annual depreciation associated with the estimated total costs of System Reinforcement; and

 

B = other benefits to the BC Hydro system, as determined by BC Hydro.

 

Based on the currently anticipated usage by Teck of the System Reinforcement and the associated revenue from Teck, the offset is sufficient to cover all the System Reinforcement costs and thus no contribution from Teck is necessary. The sufficiency of the offset will be confirmed prior to the signing of the Facilities Agreement between BC Hydro and Teck, and necessary adjustments to Teck’s contribution will be made if the offset does not cover the full System Reinforcement costs.[112]

 

BC Hydro will obtain security from Teck under the terms of Tariff Supplement No. 6 to guarantee the amount of the offset. The security will then be released in accordance with Tariff Supplement No. 6. If the expected incremental revenue from Teck materializes, all of Teck’s security provided for the System Reinforcement portion of the cost of the Project would be returned to Teck within eight years of normal operations of Teck’s facilities, starting one year after normal operations commence. However, if Teck’s load deviates significantly from the anticipated load, then all of the security may not be released.[113] 

 

Position of Parties

BCOAPO and the CEC agree that a review of Tariff Supplement No. 6 is appropriate.[114] Teck submits that it is not opposed to a review, but notes that the existing version of the tariff must be applied in the current proceeding.[115]

 

In reply, BC Hydro reiterates its view that it is time for a review of Tariff Supplement No. 6.[116]

 

Panel Determination

The Panel accepts the use of Tariff Supplement No. 6 to define the cost allocation of the Project between BC Hydro and Teck as the tariff in effect at this time. For the Project, Tariff Supplement No. 6 serves its purpose in defining the offset amount, any additional contribution and the security that Teck is obligated to provide and specifies the conditions under which the security is returned. However, Tariff Supplement No. 6 does not consider the term of service or the cost of energy, both of which may be important in determining just and reasonable rates relevant to current times.

 

The projected term of service to Highland Valley Copper is shorter than the amortization term of the Project assets. In a typical scenario a new transmission interconnection request is foreseen to be operational for an undetermined (long) period, whereas Teck’s mine life extension project is limited to 18 years.[117] In this case, the Project life is shorter than the amortization period BC Hydro is using for capital asset accounting purposes, resulting in incremental depreciation expenses that will endure longer than the period over which revenues are collected. Tariff Supplement No. 6’s use of a single year of operation for a proxy evaluation of a full Project life cycle may not be relevant for a term-limited project such as the case before us. From the 19^th year until the assets are fully depreciated in the 47^th year,[118] BC Hydro will incur costs for investing in the Project without collecting the corresponding revenue.[119]

 

The cost of energy is not considered in the calculation of the offset amount in Tariff Supplement No. 6. In 1991, when Tariff Supplement No. 6 was approved, BC Hydro had an energy surplus. As BC Hydro is expected to be in an energy deficit when the Project is in service in 2027 and to have a capacity deficit by 2031,[120] the cost allocation methodology which does not consider all costs to serve the additional load, such as the cost of energy, may not be appropriate in the future.

 

The Panel is mindful that the BCUC previously recommended a review of Tariff Supplement No. 6 in the Dawson Creek/Chetwynd Area Transmission Project (DCCAT) decision in 2012, stating it was “a significant and urgent issue.”[121] The Panel notes, however, that no such review has yet taken place.  

 

Further, the Panel notes the BC government electrification policies may increase the number of future industrial customer interconnection requests, making the need for a review of cost allocation methodology of increased importance. The Panel notes that BC Hydro is not opposed to a review of Tariff Supplement No. 6 and interveners have indicated support. For these reasons, the Panel finds that a review of Tariff Supplement No. 6 is warranted.

 

Therefore, BC Hydro is directed to file an application with the BCUC for a review of Tariff Supplement No. 6 by no later than September 30, 2025. In setting a firm deadline for an application, the Panel notes that the existing Tariff Supplement No. 6 was last reviewed and approved in 1991, more than 30 years ago, and 12 years have elapsed since the previous recommendation to review the tariff supplement in the DCCAT decision. In addition, in the interim, there has been a forecast change in BC Hydro’s energy surplus forecast and an increase in the volume of planned major infrastructure projects in the province, all of which culminate in the Panel’s conclusion of the urgency of this review.

 

In setting this deadline, the Panel communicates the urgency and importance of a review of Tariff Supplement No. 6, recognizing the review will lend regulatory certainty to industrial customers who are considering connecting to the grid in BC Hydro’s service territory. Further, almost seven months will elapse between the release of this decision and the above-stated September 2025 deadline to allow BC Hydro time for engagement with industrial customers and other stakeholders[122] on tariff amendments before filing its application.

7.0              Project Consultation and Engagement

The following subsections provide an overview of BC Hydro’s consultation and engagement activities with potentially affected Indigenous communities, local governments and the public.

7.1              Indigenous Consultation

BC Hydro identified the First Nations potentially affected by the Project using the Provincial Consultative Areas Database.[123] The Project falls within the traditional territories of the Nlaka’pamux, Secwépemc, and Syilx Okanagan Peoples, which consist of 21 individual Bands and Nations, and five First Nation representative affiliate organizations outlined in Table 3.[124]  

 

Table 3: First Nations Potentially Affected by the Project

 

 

7.1.1        Approach to Indigenous Consultation

BC Hydro states that the duty to consult aims to advance the process of reconciliation and is grounded in the honour of the Crown and section 35 of the Constitution Act, 1982. Further, BC Hydro notes that the Supreme Court of Canada’s decision in Haida Nation v. British Columbia Minister of Forests (Haida),[125] and the cases following it, established key principles that continue to guide the fulfillment of the duty to consult, including:[126]

•      The honour of the Crown is engaged when the Crown has knowledge, actual or constructive, of a potential Aboriginal right or title and contemplates a decision or conduct that may adversely affect it, thus triggering the duty to consult and, where appropriate, accommodate affected First Nations;[127]

•      The scope of consultation required in respect of contemplated Crown conduct is context-specific and proportionate to a preliminary assessment of the strength of claim supporting the existence of the right or title, and the seriousness of the potential adverse impact upon the right or title asserted;[128]

•      The concept of a “spectrum” of consultation, ranging from low to moderate to “deep” consultation, may assist in understanding what is required in the circumstances;[129]

•      The duty to consult focuses on whether there is a claim or right that may be adversely impacted by the current conduct or decision in question. Past wrongs, including previous breaches of the duty to consult, do not suffice;[130]

•      The Crown may rely on regulatory processes to partially or completely fulfill its duty to consult;[131] and

•      The Crown can still proceed in the absence of consent to the contemplated decision or conduct from a First Nation. The honour of the Crown requires a balancing of societal and First Nation interests.[132]

7.1.2        Indigenous Consultation Process

BC Hydro has assessed that the Project, after mitigation measures, will have a low to negligible impact to Aboriginal rights and title because the Project consists primarily of upgrading existing transmission line infrastructure and expansion within the existing right of way. BC Hydro acknowledges it may receive information about potential impacts as part of the consultation process.[133] Accordingly, BC Hydro asserts that the scope of consultation is not expected to exceed the moderate end of the Haida spectrum, even if the strength of claim is considered strong for any particular Nation.[134]

 

BC Hydro submits that it has meaningfully consulted and engaged with all potentially affected First Nations at a level which BC Hydro assesses has met or exceeded requirements prescribed by the Haida spectrum. BC Hydro summarizes its Project consultation process with First Nations, which started in April 2021, in Chapter 4 and Appendix K of the Application. The record of BC Hydro’s engagement consultation includes:[135]

a)       Providing Project information and updates to all potentially affected First Nations, directly or through their affiliate organizations;

b)      Soliciting First Nations’ feedback regarding the Project and its potential impacts;

c)       Where pertinent, integrating First Nations’ input in the planning process and documentation, such as the Environmental Impact Statement, the Environmental Management Plan, the Archaeological Overview Assessment and the Consultation section of the Project application to the BCUC; and

d)      Providing capacity funding to support engagement.

 

In addition, BC Hydro states it will be completing an Archaeological Impact Assessment for the new scope and First Nations will be notified and offered an opportunity to participate in the next phase of work.[136]

 

BC Hydro states that First Nations have identified the following areas of concern regarding the potential impacts of the Project:[137]

•         Potential impacts to environmental components: vegetation, fish, wildlife, habitats and water quality;

•         Land use;

•         Spiritual and cultural values; and

•         Registered archaeological sites and areas of high archaeological potential identified along the existing 1L243 transmission line.

 

Some First Nations have also expressed interest in wildlife surveys, as well as economic opportunities, including procurement, employment, and training.[138]

 

BC Hydro states that it intends to continue to engage with affected First Nations and will address issues or concerns that may arise as a result of the Project’s continued development, including from First Nations who have not provided responses to date. BC Hydro adds that it remains open to providing capacity funding should other First Nations request it.[139]  

 

On August 1, 2023, the Upper Nicola Band (UNB) communicated to BC Hydro that it does not consent to the project and that it has concerns regarding potential effects to traditional use sites, including spiritual, cultural and heritage sites. BC Hydro adds that UNB also raised concerns about the referral process being used by the Province and project proponents more generally, and stated that consent to the Project would not be granted until the Province and all proponents adequately recognized the rights held by the UNB to its land and resources. BC Hydro has continued sending Project information and trying to meet with the UNB.[140]

 

Positions of the Parties

The Lower Nicola Indian Band (LNIB) submits that BC Hydro’s consultation and accommodation is inadequate and that the BCUC is not positioned to determine if the Project is in the public interest. Accordingly, LNIB requests that the BCUC refrain from granting a CPCN for the Project until Crown consultation, which must include adequate capacity funding, is completed, and until the LNIB has the opportunity to decide if it would grant or withhold its free, prior and informed consent to the Project. LNIB also states that the BCUC has the obligation to consider the adequacy of Crown consultation in a manner that is consistent with the United Nations Declaration on the Rights of Indigenous Peoples (UNDRIP), the Declaration on the Rights of Indigenous Peoples Act[141] (DRIPA), and the constitutional imperative of reconciliation.[142]

 

In reply, BC Hydro states that BC Hydro’s consultation will continue through the planning, construction, and post-construction phases of the Project and notes that the BCUC’s role is to assess the adequacy of the consultation in the context of its decision, not to determine that consultation is “complete”.[143]

 

BC Hydro also disagrees with LNIB on the BCUC’s responsibilities in making a determination of adequacy of consultation by a Crown corporation and whether consent from potentially affected First Nations is required. BC Hydro submits that while the BCUC has the legal power to consider UNDRIP in determining whether the Project is in the public interest, DRIPA and UNDRIP do not change the BCUC’s responsibilities or standards in assessing the adequacy of consultation. In particular, BC Hydro submits that there is no requirement for LNIB to provide its consent for the Project before the BCUC can determine that consultation has been adequate.[144] BC Hydro also posits that the BCUC’s role is to assess the adequacy of consultation based on the consultation that has taken place, as set out in the evidence before it.[145]

 

In addition, BC Hydro states that it does not think it is necessary to address whether capacity funding may or may not be legally required. However, BC Hydro notes that it has offered and provided capacity funding to LNIB and that there are no outstanding requests from LNIB.[146]

 

LNIB submits that it maintains a strong assertion of Aboriginal rights and title in the Project area and that BC Hydro’s conclusions with respect to Project impacts on LNIB’s rights and title are inaccurate and contrary to its rights as affirmed by UNDRIP.[147] LNIB also argues that BC Hydro’s consultation process has not adequately addressed the potential cumulative impacts of the Project and, in particular, the impact of mining activities including Teck’s existing Highland Valley Copper mine, Teck’s Highland Valley Copper Mine Life Extension project, and associated components such as the current Project.[148]

 

BC Hydro disagrees with LNIB’s statements on strength of claim, identification of Project impacts and the scope of consultation. In its reply, BC Hydro notes that LNIB is one of several Indigenous governments and communities in the Project area. BC Hydro states that it determined that identifying each First Nation’s preliminary strength of claim was not necessary for ascertaining the adequacy of consultation, as even if the strength of claim was considered strong for any particular Nation, given the assessment of potential impacts is expected to be low, the scope of the duty to consult is not expected to exceed a moderate level on the Haida spectrum. BC Hydro further states that LNIB’s submission does not challenge BC Hydro’s determination that the scope of the duty to consult is not expected to exceed a moderate level. Further, LNIB has not requested a deeper level of consultation and engagement beyond BC Hydro’s current approach.[149] 

 

In its reply, BC Hydro also submits that since the Project consultation with LNIB started in 2021, LNIB has provided input and expressed concerns about the Project over the course of these communications, but LNIB has not provided any information about specific LNIB rights that might be affected by the Project. BC Hydro submits that it is LNIB’s responsibility to identify if there are specific aspects of LNIB’s rights and title that may be affected by the Project.[150]

 

BC Hydro, in its reply argument, states that it agrees that cumulative effects of an ongoing project, and its historical context, may inform the scope of the duty to consult and submits that its Environmental Impact Statement (EIS) assessment has considered cumulative effects. BC Hydro adds that this assessment formed part of the basis to define the Project scope of the duty to consult. BC Hydro further notes that LNIB has not raised cumulative effects/impacts as a separate and special concern during the consultation process.[151]

 

Regarding archaeological impacts, LNIB submits that there are gaps in the archaeological information which present difficulties for LNIB to make an informed assessment[152] and that all archaeological documents, procedures and trainings[153] should be prepared using LNIB’s Cultural Heritage Policy, which is currently under development, to be culturally specific and adequate. LNIB acknowledges that BC Hydro expressed willingness to follow LNIB’s policy and make BC Hydro’s “Qualified Professional” aware of LNIB’s Cultural Heritage Policy, however, LNIB “asserts BC Hydro should be required to integrate and adhere to LNIB’s Cultural Heritage Policy fully.”[154]

 

BC Hydro disagrees with LNIB’s positions on archaeological impacts. In response to LNIB’s description of the status of its documentation, BC Hydro clarifies that the Archaeological Overview Assessment (AOA) was finalized in 2022; that the Archaeological Impact Assessment (AIA) Phase 1 took place in 2023 and was shared with First Nations – including LNIB – for review and feedback; that the remainder of the AIA is planned to be completed in 2024; and that based on the current information, there are no adverse effects on archaeological resources after implementation of mitigation measures.[155] BC Hydro also disagrees with LNIB that the AIA needs to be complete for the BCUC to make a determination on adequacy of consultation. BC Hydro submits that the role of the BCUC is to make a determination in the context of its decision and does not require that the planning for the Project be completed.[156] In addition, BC Hydro disagrees that the BCUC’s determination should wait for LNIB to finalize its Cultural Heritage Policy.[157] 

 

BC Hydro also disagrees with LNIB’s criticism of its archaeological training material and processes, and LNIB’s assertion that they are culturally inadequate. BC Hydro notes that there are overlapping claims by diverse First Nations in the Project area, that BC Hydro’s materials are designed to be applicable in multiple regions in the province and that BC Hydro has already confirmed that it will work with LNIB and other identified First Nations to capture Project-related issues or concerns.[158] Further, while BC Hydro is committed to considering the Policy in its project, it states that it cannot make an unqualified commitment to integrate a policy that is under development.[159]

 

Finally, LNIB states that important environmental documentation is not finalized;[160] therefore, LNIB is uncertain about the Project specific impacts and planned mitigation measures, and LNIB does not consider it can rely solely on BC Hydro’s assurances that impacts will be minor and adequately addressed.[161]

 

In reply, with respect to environmental impacts, BC Hydro submits that there is no material uncertainty in terms of environmental effects because the Environmental Management Plan (EMP) is still in draft form, and that issues raised by LNIB have been reflected in the EIS and mitigating measures in the draft EMP.^[162]

 

Panel Determination

The Panel finds that BC Hydro’s consultation with potentially affected First Nations to the date of this decision has been adequate.

 

The Panel is satisfied that BC Hydro has identified the First Nations and Indigenous organizations potentially affected by the Project and has made adequate efforts to contact, consult and engage.

 

The Panel accepts BC Hydro's assessment that the Project, after mitigation measures, will have an overall low incremental impact on the Aboriginal rights and title of potentially affected First Nations because the Project consists mainly of upgrades and expansion of existing transmission infrastructure within the established right of way.

 

The Panel also accepts BC Hydro’s assessment that the scope of its duty to consult will not exceed the moderate end of the Haida spectrum, given the overall low impact that the Project is expected to have on Aboriginal rights and title.

 

In the Panel’s view, the evidence on the record of this proceeding demonstrates that BC Hydro has meaningfully engaged with potentially affected First Nations. In particular, the Panel notes that BC Hydro has integrated First Nations input in the planning process, such as the identification of potential project impacts in the Environmental Impact Statement.  

 

With respect to the Lower Nicola Indian Band’s (LNIB) assertion that the BCUC should refrain from granting a CPCN for the Project until consultation is complete, the Panel accepts BC Hydro’s suggestion, supported by the Kwikwetlem decision, that the BCUC’s role is to assess the adequacy of the consultation in the context of its decision, not to determine that consultation is complete. Indeed, as CPCN approval is being requested early in the Project’s lifecycle, the Panel is not surprised that consultation is incomplete, but rather expects consultation efforts to be ongoing throughout the Project.

 

With respect to LNIB’s suggestion that it should have the opportunity to grant or withhold its free, prior, and informed consent to the Project, the Panel finds that that there is no requirement for LNIB to provide its consent for the Project before the BCUC can determine whether the consultation has been adequate. The Haida decision is clear that, in general, the duty to consult does not provide potentially affected First Nations with a veto.[163] Further, with respect to LNIB’s statements regarding the BCUC’s obligations to consider UNDRIP, the Panel accepts that section 8.1 of the Interpretation Act requires legislation and regulations to be construed consistent with UNDRIP. However, following a review of the parties’ submissions, the Panel accepts BC Hydro’s submission that DRIPA does not supplant the Haida framework (which the Panel applies in this case) for assessing the adequacy of consultation.

 

With respect to LNIB’s submission that BC Hydro has not adequately addressed the potential cumulative impacts of the Project in its consultation process, the Panel notes that BC Hydro accepts that the cumulative impacts of an ongoing project may inform the scope of the duty to consult. As a result, BC Hydro submits that it has assessed cumulative impacts as part of its assessment of the scope of its duty to consult, while also noting that LNIB had not previously raised cumulative impacts as a special area of concern during the consultation process. The Panel is satisfied that BC Hydro has adequately addressed cumulative impacts as part of its consultation on the Project to date.

 

Finally, with respect to the concerns raised by LNIB with respect to BC Hydro’s archaeological assessments, the Panel accepts BC Hydro’s submission that such assessments do not need to be complete for the BCUC to determine whether consultation with LNIB has been adequate. The Panel observes that BC Hydro has circulated its archaeological assessments and engaged with all affected First Nations, including LNIB. Further, the Panel notes that BC Hydro has confirmed that it will endeavor to follow the requirements of LNIB’s Cultural Heritage Policy, depending on its completion. As noted above, the Panel expects consultation efforts to be ongoing throughout the Project, and the Panel does not consider it necessary for BC Hydro to have adhered to the LNIB’s Cultural Heritage Policy, which is not yet complete, in order to satisfy its duty to consult.

7.2              Public Engagement

BC Hydro identified the following stakeholder groups in the vicinity of the Project:[164]

•      Municipal government: District of Logan Lake, Mayor and Council;

•      Regional government: Thompson Nicola Regional District, Director, Area I;

•      Provincial government: Member of the Legislative Assembly Fraser-Nicola;

•      Several landowners along the Project’s right of way have been engaged by BC Hydro to undertake pre-construction activities such as field studies; and

•      Local rights holders and private landowners with properties adjacent to the Project area.

 

BC Hydro states that it is pursuing a public engagement approach for groups within the vicinity of the Project and other areas that may be affected by the Project that is commensurate with the level of expected potential Project impacts. Engagement activities are focused on keeping stakeholders informed of the Project timeline and activities as work progresses; and direct engagement with stakeholders on potential impacts and mitigations in an attempt to reach agreement on a resolution.

 

BC Hydro began engaging with municipal, regional, and provincial officials on the Project in January 2023. BC Hydro states that the engagement has been ongoing and is expected to continue as the Project progresses. To date, there have been no questions or concerns raised by elected officials.[165]

 

BC Hydro’s approach to the engagement of private landowners has included communication via email, telephone and in-person onsite meetings, and making a contact available to discuss private landowners’ issues. BC Hydro states that it continues to make efforts to address the issues identified by private landowners within the framework of existing policies, processes and legal requirements.[166] 

 

BC Hydro has been engaging with four private landowners whose land overlaps the Project area, specifically regarding access to statutory rights of way on private landowner property. Private landowners expressed concerns relating to work associated with the Project and potential impacts on their properties.[167] BC Hydro has agreed to limit work requiring ground disturbance for two of the private landowners, and states that negotiations for activities requiring ground disturbance will continue as the Project progresses. On July 11, 2024, BC Hydro submitted offers to acquire the statutory rights of way to the private landowners and informed them that if a consensual agreement cannot be achieved, BC Hydro may exercise its statutory powers under the Hydro and Power Authority Act to ensure access to the transmission corridor.[168]

 

Positions of the Parties

BCOAPO acknowledged BC Hydro’s success in its negotiation with affected private landowners and submits that BC Hydro’s access rights using statutory powers in the Hydro and Power Authority Act should be viewed as a last resort. BCOAPO recommends that if statutory powers are used, that BC Hydro commit to including its use in its reports or that the BCUC direct BC Hydro to include this information in annual reporting. [169]

 

Panel Determination

The Panel finds that BC Hydro’s engagement with municipal, regional and provincial governments, local rights holders and private landowners either along the Project’s right of way or in properties adjacent to the Project area, has been sufficient.

Observing that an update on Project risks, including the risk of landowner opposition, is already included in the proposed Project reporting, the Panel does not deem an additional related directive necessary.

8.0              Project Alignment with Provincial Energy Objectives and the Integrated Resource Plan

In addition to considering the interests of persons in the province who receive or may receive service from BC Hydro, section 46(3.3) of the UCA requires that the BCUC consider the following in determining whether to issue a CPCN to BC Hydro:

a) British Columbia's energy objectives;[170]

b) the most recent of the following documents:

i. an integrated resource plan approved under section 4 of the Clean Energy Act[171] before the repeal of that section;

ii. a long-term resource plan filed by BC Hydro under section 44.1 of the UCA; and

c) the extent to which the application for the CPCN is consistent with the applicable requirements under section 19 of the Clean Energy Act.

 

BC Hydro states that the Project aligns with the following eight of British Columbia’s energy objectives, set out in section 2 of the Clean Energy Act (CEA), as summarized in the table below:[172]

 

Table 4: British Columbia’s Energy Objectives[173]

 

 

 

Section 19 of the CEA, which applies to BC Hydro, addresses clean and renewable resources. However, BC Hydro states that at this time, there are no prescribed targets or guidelines under section 19 of the CEA.[177]

 

BC Hydro’s Updated 2021 Integrated Resource Plan was filed on June 15, 2023 and accepted by the BCUC on March 6, 2024.[178] BC Hydro states that the load forecast scenarios of the Updated 2021 Integrated Resource Plan, including the Reference Load Forecast, considered the increase in the mining sub-sector load.[179]

 

Position of the Parties

Teck submits that the Highland Valley Copper Mine Life Extension project is expected to provide increased employment opportunities during its construction and operation, $435 million of additional gross domestic product (GDP) during construction and support $490 million of GDP annually during operations, as well as federal, provincial and local tax revenues. For reference, in 2021 the Highland Valley Copper mine employment was approximately 1,300 employees (annual average) and municipal, provincial and federal taxes added up to approximately $200 million. Teck also submits that the Project is needed for the mine life extension project, which would extend operations of the Highland Valley Copper mine by approximately 18 years. Without it, the mine would begin closure in approximately 2028.[180]

  

Teck further states that the Project would meet provincial energy objectives related to the increased generation and use of clean electricity. In addition, it would contribute to other provincial and federal climate change and energy transition ambitions by supporting the extended life of the mine. Teck’s continued copper production would support the development of a sustainable industrial base and supply chain to support the development and production of emission-reducing technologies.[181]

 

RCIA states it believes that the Project is in the public interest, that it aligns with BC Hydro’s obligation and duty to serve increased capacity requests and further BC Hydro electrification goals for industrial projects.[182]  

 

Panel Determination

The Panel finds that the Project aligns with the applicable of British Columbia’s energy objectives as outlined in section 2 of the Clean Energy Act. In particular, the Panel agrees with BC Hydro that the Project will build infrastructure that enables transmission of electricity from clean or renewable resources, enables continued reliable transmission from BC’s heritage generation assets in BC’s Interior and supports the electrification of Teck’s Highland Valley Copper Mine Life Extension Project.

 

The Panel observes that the Project is aligned with the 2021 Integrated Resource Plan as its Reference Load Forecast considers the expected increase in demand of the mining sub-sector. The Panel also recognizes the public interest contributions made by the economic benefits that will arise from enabling the 18 years of additional mine life at Highland Valley Copper.

9.0              Overall Panel Determination

BC Hydro submits that the public interest requires the construction and operation of the Project and requests the BCUC grant a CPCN for the Project.[183]

 

Positions of the Parties

Teck submits its support for BC Hydro’s submission that the Project is in the public interest and that the BCUC grant a CPCN for the Project.[184]

 

RCIA recommends the Project be accepted as being in the public interest.[185]

 

Although the CEC finds the regulatory record to be less than adequate, the CEC recommends the BCUC grant approval of the Project as filed.[186]

 

BCOAPO supports approval of a CPCN for the Project, but submits that approval should be conditional upon Teck executing a Facilities Agreement with BC Hydro, as it is only after the execution of such an agreement that BC Hydro will be required to implement the Project.[187]

 

LNIB submits that the Application is not in the public interest because the consultation process remains incomplete and thus inadequate.[188] LNIB request that the BCUC refrain from granting a CPCN until the Crown consultation is completed and until the LNIB has had the opportunity to grant or withhold its free, prior and informed consent for the Project.[189]

 

BC Hydro’s reply to LNIB has been included in section 7 of this decision.

 

Panel Determination

For the reasons stated above in this decision, considered collectively, the Panel finds that the Project is in the public interest and that public convenience and necessity require the construction of the Project. Accordingly, the Panel grants a CPCN to BC Hydro for the Project, consisting of:

•         Reconductoring of transmission line 1L243 to increase its capacity including replaced or reinforce structures where required;

•         Supply and installation of a 300 MVA 230/138 kV/12.6 kV transformer at Nicola substation;

•         Upgrading of the disconnect switches and associated infrastructure at the Highland substation; and

•         Design and installation of a new line tap to connect Teck’s new Bethlehem substation to transmission line 1L055, to be designed and installed by Teck on behalf of BC Hydro, at Teck’s expense, and under BC Hydro’s supervision.

10.0          Project Reporting

The Panel directs BC Hydro to provide the following reports for the Project:

 

1.    Annual Progress Reports

Each report is required to detail:

•         Actual costs incurred to date compared to the Project cost breakdown table estimate provided in Table 3-3 of the Application, including the use of Project Reserve, if accessed, highlighting variances with an explanation of variances greater than 30 percent for any row number or line item;

•         Updated forecast of costs, highlighting the reasons for costs that are forecast to have variances greater than 30 percent for any row number or line item; and

•         The status of identified risks noted in Chapter 5 of the Application, highlighting the status of identified risks, changes in and additions to risks, the options available to address the risks, the actions that BC Hydro is taking to deal with the risks and the likely impact on the Project’s schedule and cost.

•         Updated actual and forecast dates for the milestones shown in Table 3-5 of the Application.

BC Hydro must file annual progress reports within 45 days of the end of each annual reporting period, with the first report covering the period ending December 31, 2025.  

 

2.    Material Change Reports

A material change (Material Change) is a change in BC Hydro’s plan for the Project that would reasonably be expected to have a significant impact on the schedule, cost or scope, such that:

•         Schedule – There is a delay in the forecast project in-service date of December 2026 provided in Table 3-5 of the Application;

•         Cost – The Authorized Cost of the Project is forecast to exceed the BC Hydro Authorized Amount of $147.1 million provided in row 15 of Table 3-3 of the Application; or  

•         Scope – There are one or more changes to the Project deliverables and the work required to create those deliverables or the main components of the Project scope detailed in Chapter 3 of the Application.

In the event of a Material Change, BC Hydro must file a Material Change report with the BCUC explaining the reasons for the Material Change, BC Hydro’s consideration of the Project risk and the options available, and actions BC Hydro is taking to address the Material Change. BC Hydro must file the Material Change report within 30 days of the Material Change occurring or within 30 days of the appropriate approval authority within BC Hydro being informed of a potential material change, whichever is earlier.

 

3.       Final Report

A Final Report is due the earlier of one month after review by BC Hydro’s Board of Directors, or 24 months after the project in-service date. The report is to include:

•         The final cost of the Project, including a breakdown of the final costs; and

•         A comparison of the final costs to the estimates provided in Table 3-3 of the Application and an explanation for any material cost variances that exceed 10 percent for any of the cost items provided in Table 3-3 of the Application.

 

 

 

Dated at the City of Vancouver, in the Province of British Columbia, this        12^th       day of February 2025.

 

 

Electronically signed by Mark Jaccard

_________________________________

M. Jaccard

Panel Chair/Commissioner

 

 

Electronically signed by Elizabeth Brown

_________________________________

E. A. Brown

Commissioner

 

 

 

 

British Columbia Hydro and Power Authority

Application for a Certificate of Public Convenience and Necessity for the 1L243 Transmission Load Increase (Highland Valley Copper) Project

 

 

 

 

British Columbia Hydro and Power Authority

Application for a Certificate of Public Convenience and Necessity for the 1L243 Transmission Load Increase (Highland Valley Copper) Project

 

 

Exhibit No.                          Description

 

Commission documents

 

A-1	June 4, 2024 - Panel Appointment
A-2	June 7, 2024 – BCUC Order G-156-24 establishing a regulatory timetable
A-3	July 3, 2024 – BCUC Information Request No. 1 to BC Hydro
A-4	July 11, 2024 – BCUC response to Colin Parkinson intervener registration
A-5	July 11, 2024 – BCUC response to BCOAPO, CEC, RCIA intervener registrations
A-6	July 11, 2024 – BCUC Order G-187-24 amending the regulatory timetable
A-7	September 19, 2024 – BCUC Order G-248-24 amending the regulatory timetable
A-8	September 25, 2024 – Panel Information Request No. 1 to BC Hydro
A-9	October 11, 2024 – Panel Request for BC Hydro’s Final Argument
A-10	November 15, 2024 – BCUC response to BCOAPO request for additional Final Argument

 

Applicant documents

 

B-1	PUBLIC - May 23, 2024 – British Columbia Hydro and Power Authority (BC Hydro) – Public Certificate of Public Convenience and Necessity (CPCN) for the 1L243 Transmission Load Increase for the Highland Valley Copper (HVC) Project - Public
B-1-1	PUBLIC - June 13, 2024 - BC Hydro CPCN for the 1L243 Transmission Load Increase for the HVC Project – Appendix H-1
B-1-2	PUBLIC – September 4, 2024 – BC Hydro submitting Errata No. 1 to the application
B-2	CONFIDENTIAL - May 23, 2024 – BC Hydro Confidential CPCN for the 1L243 Transmission Load Increase for the HVC Project
B-2-1	CONFIDENTIAL - June 13, 2024 - BC Hydro CPCN for the 1L243 Transmission Load Increase for the HVC Project – Confidential Appendix H-2
B-2-2	CONFIDENTIAL - June 13, 2024 - BC Hydro CPCN for the 1L243 Transmission Load Increase for the HVC Project – Confidential Appendix H-3
B-2-3	CONFIDENTIAL – September 4, 2024 - BC Hydro submitting Errata No. 1 to the application
B-3	July 9, 2024 – BC Hydro submitting Public Notice compliance with Order G-156-24 Directives
B-4	PUBLIC – September 4, 2024 – BC Hydro submitting response to BCUC Information Request No. 1
B-4-1	CONFIDENTIAL – September 4, 2024 – BC Hydro submitting response to BCUC Information Request No. 1
B-5	PUBLIC – September 4, 2024 – BC Hydro submitting response to Intervener Information Request No. 1
B-5-1	CONFIDENTIAL – September 4, 2024 – BC Hydro submitting response to Intervener Information Request No. 1
B-6	CONFIDENTIAL – September 4, 2024 – BC Hydro submitting response to Confidential Intervener Information Request No. 1
B-7	PUBLIC – October 3, 2024 – BC Hydro submitting response to Panel Information Request No. 1
B-7-1	CONFIDENTIAL – October 3, 2024 – BC Hydro submitting response to Panel Information Request No. 1

 

 

Intervener documents

 

C1-1	June 12, 2024 – Colin Parkinson (Parkinson) – Request to intervene
C2-1	June 17, 2024 – Residential Consumer Intervener Association (RCIA) – Request to intervene by Rory MacGregor
C2-2	June 14, 2024 – RCIA submitting Confidentiality Declaration and Undertaking Forms
C3-1	June 28, 2024 – British Columbia Old Age Pensioners’ Organization et al. (BCOAPO) – Request to intervene by Irina Mis
C3-2	July 16, 2024 – BCOAPO submitting Confidentiality Declaration and Undertaking Forms
C3-3	July 25, 2024 – BCOAPO submitting additional Confidentiality Declaration and Undertaking Form
C3-4	PUBLIC - July 31, 2024 – BCOAPO, CEC and RCIA submitting Information Request No. 1
C3-4-1	CONFIDENTIAL - July 31, 2024 – BCOAPO submitting Information Request No. 1
C4-1	June 28, 2024 – Lower Nicola Indian Band (LNIB) – Request to intervene by Aidan Whiteley
C4-2	July 30, 2024 – LNIB submitting Confidentiality Declaration and Undertaking Forms
C4-3	July 31, 2024 – LNIB submitting Information Request No. 1
C4-4	October 28, 2024 – LNIB submitting Confidentiality Declaration and Undertaking Form
C5-1	July 2, 2024 – Commercial Energy Consumers Association of BC (CEC) – Request to intervene by David Craig
C5-2	July 25, 2024 – CEC submitting Confidentiality Declaration and Undertaking Form-E. Gjoshe
C6-1	July 2, 2024 – Teck Highland Valley Copper Partnership (HVC) – Request to intervene by Glenda Fratton
C6-2	July 2, 2024 – HVC Submission
C6-3	July 30, 2024 – HVC submitting Confidentiality Declaration and Undertaking Forms
C7-1	July 2, 2024 – Nlaka'pamux Nation Tribal Council (NNTC) – Request to intervene by Debbie Abbott
C7-2	July 30, 2024 – NNTC submitting Information Request No. 1 to BC Hydro